Water produced from well treatment operations, including stimulation operations for enhancing the recovery of hydrocarbons from subterranean formations, is often laden with a significant concentration of contaminants.
A common stimulation operation is hydraulic fracturing wherein fractures are created in subterranean formations which extend from the wellbore into the rock. The rate at which fluids can be produced from the formation is increased by this operation. The treatment design generally requires the fluid to reach maximum viscosity as it enters the fracture in order to transport proppant into the formation. Viscosifying polymers are often included in the fluid in order to provide the requisite viscosity. Proppant remains in the produced fracture to prevent the complete closure of the fracture and to form a conductive channel extending from the wellbore into the treated formation. Once the high viscosity fluid has carried the proppant into the formation, breakers reduce the fluid's viscosity.
Typically, a large amount of water is used during a stimulation operation. For instance, during a hydraulic fracturing operation, water is pumped into fractures at pressures exceeding 3000 psi and flow rates exceeding 85 gallons per minute. A horizontal well with a 4,500 foot lateral bore may use about 4 to 5 million gallons of water.
In addition to facilitating settling of the proppant in the fracture, breakers also facilitate fluid flowback to the well. The fluid which returns to the surface from a fracturing operation is either flowback water or produced water. In addition to natural salinity of water in the formation, fresh water that is forced down a well during the fracturing operation tends to dissolve salts in the formation thus giving the recovered water very high salinity. Thus, flowback water typically is characterized by high salinity and dissolved solids and often contains the same chemicals which are pumped into the well. In addition, flowback water contains contaminants which are present in rock formation water. Flowback of fluids from the well requires a high volume of water. In some instances, the volume of water may be as high as 40,000 bbl.
At a point in the treatment operation, there is a transition between flowback water to produced water. Produced water contains clay, dirt, metals, chemicals and even diesel that may have been added during the operation. After the recovery of flowback fluids, an additional 10,000 to 30,000 bbl of produced water may flow for up to two years. The point at which flowback water becomes produced water is difficult to distinguish, yet may be discerned from the chemistry of flowback water versus naturally occurring water produced by the formation.
Increased interest in minimizing environmental risk from chemicals has led to the development of alternative breakers for use in high-temperature fluids. While enzymes have been used for many years, their use is often limited due to polymer specificity and thermal stability. Breakers derived from biological sources and displaying catalytic, polymer degrading activity has been reported in U.S. Pat. No. 9,090,814. Being catalytic, renewable, biodegradable and non polymer-specific, such breakers do not display the thermal denaturation limitations of enzyme breakers and thus can be used over wider temperature range. Such breakers include vitamin B1 which has now been examined for use in the recycling of flowback water and produced water.
It should be understood that the above-described discussion is provided for illustrative purposes only and is not intended to limit the scope or subject matter of the appended claims or those of any related patent application or patent. Thus, none of the appended claims or claims of any related application or patent should be limited by the above discussion or construed to address, include or exclude each or any of the above-cited features or disadvantages merely because of the mention thereof herein.